1. Field of the Invention
The present invention relates generally to buoyancy for offshore oil production.
2. Related Art
As the cost of oil increases and/or the supply of readily accessible oil reserves are depleted, less productive or more distant oil reserves are targeted, and oil producers are pushed to greater extremes to extract oil from less productive oil reserves, or to reach more distant oil reserves. Such distant oil reserves may be located below the oceans, and oil producers have developed offshore drilling platforms in an effort to extend their reach to these oil reserves. In addition, some oil reserves are located farther offshore, and thousands of feet below the surface of the oceans.
For example, vast oil reservoirs have recently been discovered in very deep waters around the world, principally in the Gulf of Mexico, Brazil and West Africa. Water depths for these discoveries range from 1500 to nearly 10,000 ft. Conventional offshore oil production methods using a fixed truss type platform are not suitable for these water depths. These platforms become dynamically active (flexible) in these water depths. Stiffening them to avoid excessive and damaging dynamic responses to wave forces is prohibitively expensive.
Deep-water oil and gas production has thus turned to new technologies based on floating production systems. These systems come in several forms, but all of them rely on buoyancy for support and some form of a mooring system for lateral restraint against the environmental forces of wind, waves and current.
These floating production systems (FPS) sometimes are used for drilling as well as production. They are also sometimes used for storing oil for offloading to a tanker. This is most common in Brazil and West Africa, but not in Gulf of Mexico as of yet. In the Gulf of Mexico, oil and gas are exported through pipelines to shore.
Certain floating oil platforms, i.e., Spars or Deep Draft Caisson Vessels (DDCV), and large “Semi-submersibles” have been developed to reach these deep-water oil reserves. Most of these floating platforms are designed to maximize the platform's ability to produce and process crude oil (thus maximizing revenue), while at the same time minimize the overall size and mass of the platform hull and thus minimize the required capital investment. For this reason, it is advantageous to utilize the available hull buoyancy for topside processing equipment, and to minimize or even decouple other “parasitic” weight that would otherwise increase capital costs or reduce revenue-generating payload.
Steel tubes or pipes, known as risers, are suspended from these floating platforms, and extend the thousands of feet to reach the ocean floor, and the oil reserves beyond.
Typical risers are either vertical (or nearly vertical) pipes held up at the surface by tensioning devices (called Top Tensioned riser); or flexible pipes which are supported at the top and formed in a modified catenary shape to the sea bed; or steel pipe which is also supported at the top and configured in a catenary to the sea bed (Steel Catenary Risers—commonly known as SCRs).
The flexible and SCR type risers may in most cases be directly attached to the floating vessel. Their catenary shapes allow them to comply with the motions of the FPS caused by environmental forces. These motions can be as much as 10-20% of the water depth horizontally, and 10s of feet vertically, depending on the type of vessel, mooring and location.
Top Tensioned Risers (TTRs) typically need to have higher tensions than the flexible risers, and the vertical motions of the vessel need to be isolated from the risers. TTRs have significant advantages for production over the other forms of risers, however, because they allow the wells to be drilled directly from the FPS, avoiding an expensive separate floating drilling rig. Also, wellhead control valves placed on board the FPS allow for the wells to be maintained from the FPS. Flexible and SCR type production risers require the wellhead control valves to be placed on the seabed where access is difficult and maintenance is expensive. These surface wellhead and subsurface wellhead systems are commonly referred to as “Dry Tree” and “Wet Tree” types of production systems, respectively. Drilling risers must be of the TTR type to allow for drill pipe rotation within the riser. Export risers may be of either type.
TTR tensioning systems are a technical challenge, especially in very deep water where the required top tensions can be 1,000,000 lbs (1,000 kips) or more. Some types of FPS vessels, e.g. ship shaped hulls, have extreme motions which are too large for TTRs. These types of vessels are only suitable for flexible risers, or other free-standing systems. Other, low heave (vertical motion), FPS designs are suitable for TTRs. This includes Tension Leg Platforms (TLP), Semi-submersibles and Spars, all of which are in service today.
One type of riser tensioning system that may be employed calls for buoyancy that is distributed along the vertical length of the riser. Depending on the total weight of each riser (which determines how much net buoyancy is desired) and other requirements, it may be more advantageous to attach buoyant elements along the entire length of the riser system, rather than to concentrate all the buoyancy near the system's upper end.
Of the aforementioned floating production systems, only the TLP and Spar platforms use TTR production risers. Semi-submersibles may use TTRs for drilling risers, but these must be disconnected in extreme weather. Production risers need to be designed to remain connected to the seabed in extreme events, typically the 100 year return period storm. Only very stable vessels, such as TLPs and Spars are suitable for this.
Early TTR designs employed on semi-submersibles and TLPs used active hydraulic tensioners to support the risers by keeping the tension relatively constant during wave motions. As tensions and stroke requirements grow, these active tensioners become prohibitively expensive. They also require large deck area, and the buoyancy loads have to be carried by the FPS structure.
Spar type platforms recently used in the Gulf of Mexico use a passive means for tensioning the risers. These type platforms have a very deep draft with a central shaft, or centerwell, through which the risers pass. Types of spars include the Caisson Spar (cylindrical), the “Truss” spar and “Cell” spar. There may be as many as 40 production risers passing through a single centerwell. Even the most recent designs for large buoyancy cans used on Spars are limited in diameter and overall length, and may not be feasible or cost-effective where the net buoyancy requirement is in the range of 3000-4000 kips. This may be driven by the need to employ very heavy wall, or double wall riser pipe systems. In cases such as this, it may be more cost-effective to utilize a system of distributed buoyancy elements, rather than conventional air cans used on TTRs.
The underlying principal of both TTR buoyancy cans and distributed buoyancy systems is to remove a load-bearing connection between the floating vessel and the risers. Whether located at the top of the riser system (near the water surface) or distributed along the riser's total length, the buoyant elements need to provide enough buoyancy to support the required tension in the risers, the weight of the buoyant elements, and the weight of the surface wellhead. One disadvantage with TTR air cans is that they are normally formed of metal, and thus add considerable weight themselves. Thus, the metal air cans must support the weight of the risers and themselves. In addition, the air cans are often built to pressure vessel specifications, and are thus costly and time consuming to manufacture.
Conventional designs for distributed buoyancy systems are based on foam-filled, half-round sections that are mechanically attached (bolted) around a riser pipe. Storage and staging of these buoyancy sections can be a cumbersome task on an offshore platform, where open deck space is all but nonexistent. Installation is likewise time-consuming and requires heavy tools.
As risers have become longer by going deeper, their weight has increased substantially. One solution to this problem has been to simply increase the number of buoyant sections added to each riser string, since the maximum diameter of said buoyant shells is normally limited to that which will pass through the rotary table while the riser joints are being “run,” or assembled and lowered into the water.
One problem with typical buoyancy systems is that if they are top tensioned, and the buoyancy force is concentrated at the top of the riser, it may result in higher stress, strain and/or force concentrations. Another problem with buoyancy is water pressure, especially at greater depths, that can crush conventional buoyancy cans or the like. While some buoyancy systems resolve that problem by utilizing expensive, crush-resistant foams, the foams themselves are usually very dense and can be very expensive. Yet another problem with providing buoyancy is transportation of the buoyancy system to the drill site, or the offshore platform. A related problem is the expense and difficulty of installing and/or assembling the buoyancy system. Many systems can be labor intensive and inefficient to install.